1. Field of the Invention
This invention pertains to the field of purifying fluid streams by the removal of at least sulfur compounds therefrom. More particularly, the present invention relates to a new and integrated process which involves the utilization of a primary adsorption bed containing a regenerable, physical adsorbent and an auxiliary sorption bed containing a chemisorbent for the removal of sulfur compounds from the fluid stream, which process provides for higher yields and product purity while at the same time generally requires less energy consumption and/or capital costs.
2. Discussion of Related Art
The removal of sulfur compounds, particularly hydrogen sulfide and alkyl mercaptans from hydrocarbon streams is desirable for many reasons, depending in part upon the intended use of the final sweetened product. Since a very large percentage of the lighter hydrocarbons in liquid streams are ultimately used as fuel per se, the presence of sulfur compounds is objectionable because of the safety factors and corrosion problems associated with such compounds and the unpleasant odor imparted and the air pollution resulting from the combustion thereof. When used as fuels for internal-combustion engines, the sulfur compounds are deleterious to the effectiveness of known octane improvers such as tetraethyllead. The hydrocarbon streams are also generally subjected to hydrocarbon conversion processes in which the conversion catalysts are, as a rule, highly susceptible to poisoning by sulfur compounds.
So too, the tremendous increase in demand for natural gas in recent years has made the gas producers far more dependent on "sour" gas fields than ever before. As used herein, a "sour" gas is defined as a gas containing mercaptans and/or hydrogen sulfide. "Sweetening" is defined as the removal of the mercaptans and hydrogen sulfide from a gas or liquid stream. Formerly, when a gas well came in "sour", it was capped off because the supply and demand situation did not permit its purification. Recently, however, these capped wells have been put into production and are being utilized regardless of their hydrogen sulfide and mercaptan content.
Several methods for sweetening hydrocarbons streams have been proposed and utilized in the past, including both chemical and physical techniques.
The chemical processes have involved purely chemical reactions such as scrubbing with mono- or diethanolamine or countercurrent extraction using a hot potassium carbonate solution, and chemisorption methods in which iron oxide sponge or zinc oxide reacts with the sulfur compounds to form iron sulfide and zinc sulfide, respectively.
A widely used chemical system for treating natural gas streams involves scrubbing with mono- or diethanolamine. The natural gas is passed through the amine solution which absorbs the hydrogen sulfide. The solution from the absorption equipment is passed to a stripping column where heat is applied to boil the solution and release the hydrogen sulfide. The lean, stripped solution is then passed to heat exchangers, and returned to the absorption equipment to again absorb hydrogen sulfide gas. The principle disadvantages of the amine system are its high operating cost, the corrosive nature of the absorbing liquid, its inability to remove mercaptans and water from gas streams, as well as its general inability to selectively remove hydrogen sulfide from carbon dioxide.
Another prior art system is the iron sponge method of purifying natural gas, utilizing iron oxide impregnated wood chips in a packed bed. The gaseous mixture containing hydrogen sulfide and/or mercaptans contacts a packed bed of iron oxide sponge, preferably chemically absorbing the sulfur impurities on the exposed iron oxide surface. A major disadvantage of this method of sweetening natural gas is that the fusion of iron sponge particles with sulfur frequently causes a high pressure drop through the bed. Moreover, the operational cost is high because the adsorbent must be replaced frequently. Finally, the iron sulfide is pyrophoric and thus presents serious problems with the disposal of the used iron oxide.
Hydrogen sulfide has also been removed from natural gas by countercurrent extraction with a hot potassium carbonate solution. In such a system, as in the amine system discussed above, both hydrogen sulfide and carbon dioxide are removed by chemically combining with potassium carbonate and later released by stripping with steam. Generally, significant disadvantages of this method of sweetening natural gas are that an amine system must ffollow the potassium carbonate system to remove the final traces of the sulfur compounds such as hydrogen sulfide and the non-selectivity for removing the hydrogen sulfide from the carbon dioxide.
Zinc oxide has also been used for removing sulfur compounds from hydrocarbon streams. However, its high cost and substantial regeneration costs make it generally uneconomical to treat hydrocarbon streams containing an appreciable amount of sulfur compound impurities on a volume basis. So too, the use of zinc oxide and other chemisorption material similar to it disadvantageously generally require the additional energy expenditure of having to heat the sulfur containing fluid stream prior to its being contacted with the stream in order to obtain a desirable sulfur compound loading characteristic.
Selective physical adsorption of sulfur impurities on crystalline zeolitic molecular sieves is a widely used method. Both liquid phase and vapor phase processes have been developed. As used herein, a "physical adsorbent" is an adsorbent which does not chemically react with the impurities that it removes.
A typical hydrocarbon sweetening process comprises passing a sulfur-containing hydrocarbon stream through a bed of a molecular sieve adsorbent having a pore size large enough to adsorb the sulfur impurities, recovering the non-adsorbed effluent hydrocarbon until a desired degree of loading of the adsorbent with sulfur-containing impurities is obtained, and thereafter purging the adsorbent mass of hydrocarbon and regenerating the adsorbent by desorbing the sulfur-containing compounds therefrom.
The adsorbent regenerating operation is conventionally a thermal swing or combined thermal and pressure swing-type operation in which the heat input is supplied by a hot gas substantially inert toward the hydrocarbons, the molecular sieve adsorbents and the sulfur-containing adsorbate. When treating a hydrocarbon in the liquid phase, such as propane, butane or liquified petroleum gas (LPG), natural gas is ideally suited for use in purging and adsorbent regeneration, provided that it can subsequently be utilized in situ as a fuel wherein it constitutes an economic balance against its relatively high cost. Frequently, however, the sweetening operation requires more natural gas for thermal-swing regeneration than can advantageously be consumed as fuel, and therefore, constitutes an inadequacy of the regeneration gas. The result is a serious impediment to successful design and operation of sweetening processes, especially when desulfurization is carried out at a location remote from the refinery, as is frequently the case.
But even when treating a hydrocarbon in the gaseous phase with a physical adsorbent such as crystalline zeolitic molecular sieves, a purge gas must still be provided to regenerate the sulfur-compound laden adsorbent, involving the same disadvantages noted above when using a liquid phase hydrocarbon stream. Generally, a product slip-stream from an adsorbent bed in the adsorption mode is utilized as the desorption gas for regenerating a used bed. The utilization of this product gas for regeneration purposes during the entire adsorption cycle disadvantageously reduces the final product yield. Moreover, it is generally difficult to get complete sulfur-compound removal when utilizing such a physical adsorbent.
A need consequently exists to provide a process for removing sulfur-compounds from a liquid or gaseous stream which process is more economical and efficient than the prior art techniques discussed above.